1. Field of the Invention
The present invention relates in general to the decontamination of flue gas and particularly to a new and useful method to recover fly ash, sulfur oxides and/or other contaminants contained in flue gases, as well as recovering ammonium salt reaction products and ammonia slip which results as a waste product of selective catalytic reaction of the oxides of nitrogen.
2. Description of the Related Art
There are several systems relating to integrated heat recovery and the removal of particulates, sulfur oxides/acid gases and contaminants from a hot combustion exhaust gas in order to comply with federal and state requirements.
One system, which is shown in FIG. 1, is a condensing heat exchanger, generally designated 10, which recovers both sensible and latent heat from flue gas 11 in a single unit. The arrangement allows for the gas 11 to pass down through heat exchanger 12 while water 14 passes upward in a serpentine path through Teflon, a registered trademark of Du Pont Corp., covered tubes 13. Condensation occurs within the heat exchanger 12 as the gas temperature at the tube surface is brought below the dew point. The condensate falls as a constant rain over the tube array and is removed at the bottom at outlet 16. Gas cleaning can occur within the heat exchanger 12 by the mechanisms of absorption, condensation and impaction as the gas 11 is cooled below the dew point.
The heat exchanger tubes 13 FIGS. 2b and 2c and inside surfaces of heat exchanger shell 15 are made of or covered with a corrosion resistant material. One such corrosion resistant covering is fluoroplastic such as fluorinated ethylene propylene (FEP, tetrafluoroethylene (TFE) or polytetrafluoroethylene (PTFE) like Teflon 17, a registered trademark of Du Pont Corp. The selection of material protects the heat exchanger from corrosion when the flue gas temperature is brought below the acid dew point. Interconnections between the heat exchanger tubes 13 are made outside the tube sheet 15 through holes 19 which are sealed by Teflon seal 18 and are not exposed to the corrosive flue gas stream 11. The modular design of this heat exchanger is shown in FIG. 2a.
It should be noted that while the heat exchanger is called a condensing heat exchanger, condensation does not occur under all conditions or on all surfaces. Condensation will occur when the tube surfaces are brought below the dewpoint of the condensible gas. The condensing heat exchanger is specifically constructed of corrosion zesistant materials for survival under condensing conditions and during washing.
Another system used in this area is an integrated flue gas treatment (IFGT) condensing heat exchanger, generally designated 20, which is schematically shown in FIG. 3. Condensing heat exchanger unit 20 is designed to enhance the removal of pollutants, particulate, sulfur oxides/acid gases and other contaminants from flue gas stream 22. It is also made of corrosion resistant material or has all of the inside surfaces covered by Teflon, or like material.
There are four major sections of the IFGT 20: a first heat exchanger stage 24, an interstage transition region 26, a second heat exchanger stage 28, and a mist eliminator 30. The major differences between the integrated flue gas treatment design of FIG. 3 and the conventional condensing heat exchanger design of FIG. 1 are:
1. the integrated flue gas treatment design uses two heat exchanger stages 24 and 28 instead of one heat exchanger 12. (FIG. 1);
2. the interstage or transition region 26, located between heat exchanger stages 24 and 28, is used to direct the gas 22 to the second heat exchanger stage 28, and acts as a collection tank and allows for treatment of the gas 22 between the stages 24 and 28;
3. the gas flow in the second heat exchanger stage 28 is upward, rather than downward;
4. gas outlet 29 of the second heat exchanger stage is equipped with an alkali reagent spray system, generally designated 40, comprising reagent source 42 with a pump 44 for pumping reagent 42 to sprayers 46; and
5. the mist eliminator 30 is used to separate the water formed by condensation and sprays from the flue gas.
Most of the sensible heat is removed from the gas 22 in the first heat exchanger stage 24 of the IFGT 20. The transition region 26 can be equipped with a water or alkali spray system 48. The system 20 saturates the flue gas 22 with moisture before it enters the second heat exchanger stage 28 and also assists in removing particulate, sulfur pollutants, acid gases and other contaminants from the gas 22.
The transition piece 26 is made of corrosion resistant material like fiberglass-reinforced plastic. Additionally, the second heat exchanger stage 28 is operated in the condensing mode, removing latent heat from the gas 22 along with pollutants. Also, the top of this second heat exchanger stage 28 is equipped with an alkali solution spray device 46. The gas 22 in this stage 28 is flowing upward while the droplets in the gas 22 fall downward. This counter-current gas/droplet flow provides a scrubbing mechanism that enhances particulate and pollutant capture. The captured particulate, sulfur oxides/acid gases and contaminants that are contained in the falling condensate/reacted alkali droplets flow downward and are collected at the bottom of the transition section 26. The flue gas outlet 29 of the IFGT 20 is equipped with the mist eliminator 30 to reduce the chance of moisture carryover.
Other treatment methods include wet chemical absorption processes, i.e. the use of wet scrubbers such as the unit 50 shown in FIG. 4, and in particular those applications where the hot gas 22 is typically washed in an upflow gas-liquid contact device 52 (i.e. spray tower) with an aqueous alkaline solution or slurry by sprayers 54 in order to remove sulfur oxides and/or other contaminants from the gas 22.
Wet chemical absorption systems installed by electric power generating plants typically utilize calcium, magnesium or sodium based process chemistries, with or without the use of additives, for flue gas desulfurization.
Additionally, wet scrubbing systems are used as described in U.S. Pat. No. 4,263,021 which utilizes a gas-liquid contact system for obtaining counter-current gas-liquid contact between a flue gas containing sulfur dioxide and a aqueous slurry solution. This system is currently referred to as a tray or gas distribution device.
Other wet scrubber devices utilize various types of packing inside the spray tower to improve gas-liquid distribution which works well with clear solution chemistry processes, but are prone to gas channeling and pluggage in slurry services.
Most of the wet scrubbers use mist eliminators, normally 2-3 stages, in order to remove entrained water droplets from the scrubber gas.
Selective catalytic reduction (SCR) systems are also known which catalytically reduce NO.sub.x from flue gas formed during the combustion of waste materials, coal, oil and other fossil fuels, which are burned by power generating plants and other industrial processes to nitrogen (N.sub.2) and water (H.sub.2 O) using ammonia (NH.sub.3) in a chemical reduction process. SCR systems provide the most effective method of reducing NO.sub.x emissions especially where high reduction percentages (70-90%) or low stack emission levels are required. NO.sub.x emissions from boilers are typically 90 to 95% nitrogen oxide (NO) with the balance being nitrogen dioxide (NO.sub.2). However, when the flue gas is discharged from the stack, the bulk of the NO is oxidized to NO.sub.2 which reacts in the environment producing smog constituents and acid rain.
For combustion processes utilizing SCR systems, the catalyst is housed in a reactor which is strategically located within the flue gas system. This location permits catalyst exposure to proper SCR reaction temperatures. The reactor design includes a sealing system to prevent flue gas bypassing and an internal support for structural stability of the catalyst. The reactor configuration can be vertical or horizontal depending on the fuel used, space available and upstream/downstream equipment arrangement.
Ammonia (NH.sub.3) is introduced upstream of the SCR reactor either in the form of anhydrous ammonia or vaporized aqueous ammonia. Uniform flow distribution of ammonia is required for optimum performance, therefore, the ammonia vapor is diluted with air or recirculated flue gas to provide the mass necessary to distribute the ammonia evenly over the fluework cross-section. The diluted ammonia mixture is delivered to a grid of injection pipes located in the fluework. Although the ammonia is distributed uniformly across the flue cross-section, some ammonia passes through the catalyst bed unreacted. The unreacted ammonia is known as NH.sub.3 slip. Since the NH.sub.3 slip will combine with sulfur trioxide (SO.sub.3) and sulfur dioxide (SO.sub.2) at temperatures experienced downstream of the SCR, the downstream equipment tends to get fouled by the deposition of ammonium salts. The fouling results in increased maintenance and repair costs for the equipment and decreased reliability and overall performance for the plant.
It is well documented that combustion processes typically produce sulfur dioxide (SO.sub.2) and sulfur trioxide (SOB). Sulfur trioxide is typically produced in much smaller quantities. However, one known problem with using SCR technology on processes which burn sulfur-laden fuels is the oxidation of SO.sub.2 to SO.sub.3. The SCR catalyst oxidizes sulfur dioxide to sulfur trioxide as the flue gas passes through the catalyst bed. The SO.sub.3 then combines with the NH.sub.3 slip to form ammonium salts which tend to foul downstream equipment.
SCR catalyst manufacturers have combated the problem to some extent by formulating catalysts which are less reactive. Hence, the SO.sub.2 oxidation rate is much less. The disadvantage to using lower activity catalyst is that more catalyst is required to achieve the same NO.sub.x reduction. Moreover, the per-unit catalyst price is sometimes higher because of the special formulation.
In view of the foregoing, it is seen that an efficient system for removing flue gas NO.sub.x while minimizing the threat of ammonium salt deposition on downstream equipment is needed which would be both cost and operationally effective. Furthermore, it is seen that an efficient system was needed to enable a condensing heat exchanger system to capture ammonium salts without compromising heat transfer efficiency.